The present disclosure is directed to a process of removal of H.sub.2 S from a natural gas stream. In a typical situation, many gathering lines from producing gas wells are brought together, the gas is passed through a compressor and raised to some elevated pressure, and is delivered into a pipeline. Typically, the gathering lines will come together at a collection point in a gas field at which location appropriate compressors and stripping devices are incorporated. These are normally unmanned devices which are serviced only periodically. The present disclosure is directed to a system which can be installed at the gathering location for stripping H.sub.2 S from the gas. It is well known that H.sub.2 S in natural gas creates a number of problems. It is therefore desirable for the H.sub.2 S to be removed from the natural gas. Typically at the compressor location, heavy molecules are stripped from the gas, and any liquids (oil or salt water) that are produced with the gas are also stripped. Also, sand from the wells is also stripped. After stripping, the gas is compressed, raised to some elevated pressure and is delivered into a line from the field for subsequent delivery.
Numerous efforts have been made in the past to provide field installed, typically unmanned H.sub.2 S stripping procedures. Three references for this process include U.S. Pat. Nos. 4,008,251, 4,515,759 and U.S. Pat. No. 4,451,442. The '442 reference is directed to H.sub.2 S removal by contact with an aqueous solution of a polyvalent metal chelate and oxidizing agent. The metal chelate is reduced to a lower oxidation state, then raised to the higher oxidation state, and is recycled between states to permit reuse. That disclosure sets forth various oxidizing agents and prefers SO.sub.2 with alkali metal salts of typical inorganic oxidizers such as chloric, perchloric, hypochlorous and permanganic acids. The chelate utilizes polyvalent metals comprising a rather lengthy list and identifies an even longer list of chelating agents. The '759 reference is directed primarily to water soluble nitrites, the preferred being sodium nitrite. That process is preferably conducted at a pH of 5.5 or greater. The oxidizer of the '759 disclosure, being nitrite, is relatively similar to the list of oxidizers described in the '442 reference. The '251 reference mentioned above discloses treatment of the gas stream in the presence of oxygen bubbled through an aqueous solution, the solution having a water soluble polyvalent metal chelate catalyst which retains the metal in solution, having a pH of about 3 to about 11. The preferred form is the appropriate salt oxide or hydroxide utilizing a alkali metal or NH.sub.4.sup.+ salt.
These references come at the matter with some difficulty. Consider for instance, the '251 reference. Ideally, pure oxygen is used as the oxidizing agent. In the field, and especially at remote locations, this would require a source of liquid oxygen which is relatively expensive to keep and maintain at untended locations and which is somewhat more expensive to operate. Moreover, air can be used in place of that but 80% of air is nitrogen which would otherwise be bubbled up through the standing column of water in which the contact process is carried out and would mix with the natural gas stream. Thus, the air injected into the water tower for conducting the process would inevitably dilute the natural gas by adding nitrogen to it. Compression and delivery costs would then be raised because the nitrogen in the natural gas stream might well be transported the full length of the pipeline system and would simply dilute the required btu output of the natural gas stream.
The '442 reference generally relies on the polyvalent state of the metal chelate for recYcling. Moreover, it teaches use of SO.sub.2 as an oxidizing material. In an example typical of that disclosure, it begins with Fe.sup.+3 which is reduced to Fe.sup.+2 and recycled again. The foregoing is carried out for the purpose of converting H.sub.2 S to free sulfur and then to various soluble sulfur compounds. As will be understood, the transition from H.sub.2 S through the free sulfur state is accomplished in solution: the process mentions the formation of free sulfur but the resultant material is sulfur compounds, not free sulfur. It is suggested that soluble sulfur compounds are less desirable than the free sulfur obtained in the present disclosure. So to speak, the '442 process overruns the goal because the production of water soluble sulfur compounds greatly increases the requirement of needed oxidant over that required to produce elemental sulfur.
The '759 process utilizes sodium nitrite. That is highly inefficient as will be illustrated in the present disclosure. One hypothesis for the inefficiency of that process is derived from a discussion of that process involving one of the inventor's thereof which was published in the Oil & Gas Journal on Oct. 20, 1986 at Page 44. In analysis of the process, the H.sub.2 S in solution with NO.sub.2.sup.- certainly yields some sulfur, but it also yields NH.sub.3. Because of the kinetics of the reaction in solution, there appears to be competing and preferential activity from NH.sub.3. The NH.sub.3, apparently sustained in solution indefinitely so long as the process is carried out, limits the effectiveness of the less active NO.sub.2.sup.-, thereby reducing the relative efficiency of that process. As will be detailed in the present disclosure, marked advances in process efficiency per unit weight of oxidizer have been shown, and moreover, they are accomplished apparently with the suppression of NH.sub.3 formation so that more of the bound nitrogen stays in the form of NO.sub.2.sup.- and process efficiency is remarkably higher. More will be noted concerning this on a review of the detailed description of the preferred embodiment.